The present invention relates generally to an apparatus for venting sustained casing pressure buildups in nested annuli of a downhole casing assembly, and more particularly to a trapped annular pressure relief collar, which passes the pressurized fluid toward the innermost annuli of the downhole casing assembly.
The Minerals Management Service (MMS) of the U.S. Department of the Interior is concerned about wells on the outer continental shelf that exhibit significant sustained casing pressure (SCP) because Congress has mandated that the MMS is responsible for worker safety and environmental protection. Sustained casing pressure is defined as pressure between the casing and the well's tubing, or between strings of casing, that rebuilds after being bled down. Sustained casing pressure is not due solely to temperature fluctuations nor is sustained casing pressure a pressure that has been deliberately applied, such as in a gas-lift scenario. In some respects, a small amount of sustained casing pressure in one or more annuli of a well may be viewed as inevitable in the operational life of a well, particularly when the well is operated well beyond its originally intended design life. However, a larger amount of sustained casing pressure can lead to a loss of well control (e.g., a blowout), a casing rupture or collapse, or the possible leakage of hydrocarbons outside of the well.
Sustained casing pressure can result from tubing leaks, casing leaks, and the establishment of flow paths through the cemented annulus due to poor primary cement quality, or damage to the primary cement after setting, and formations above the top of cement in each annuli. Tubing or casing leaks can result from a poor thread connection, corrosion, thermal-stress cracking, or mechanical rupture of the inner string. Wells are designed so that the innermost casings are the strongest for pressure containment. Only the production casing is generally designed to withstand the pressure of the deepest producing formation. Thus, production casing provides a redundant barrier to a blowout in the event of a failure of the production tubing, which allows the production tubing to be safely repaired. If the production casing fails, the next outer casing string is generally not designed to withstand formation pressure.
Sustained casing pressure can also originate within the same annulus experiencing the pressure build-up. Portland cement has been used by the oil and gas industry since the early 1900's as the primary means of sealing the area between the open borehole and the casing placed in the well. When set, some commonly used Portland cement formulations form brittle materials that are susceptible to cracking when exposed to thermally induced or pressure induced tensile loads. A primary cement job can be compromised in several ways to provide flow paths for gas migration. The most common problem occurring during primary cementing is the invasion of gas into the cement during the setting process. This may occur as cement gels and loses the ability to transmit hydrostatic pressure needed to hold back water and/or gas from formations. This can result in channels in the cement caused by flow from a formation after cementing. Mud quality while drilling can also affect the quality of the primary cement job. If the mud weight is too low, the result is borehole instability leading to borehole enlargements. Borehole enlargements and mudcake against the borehole that is not properly removed prior to cementing can cause poor bonding between cement and borehole, resulting in potential leak paths.
Even a flawless primary cement job can be damaged by common operations occurring after the cement has set. The casing and cement do not behave in a uniform manner due to the greatly differing ductile properties of metal and common types of cement. As a well is completed and produced the tubulars experience pressure and temperature cycles. This can result in casing diameter/length shrinkage and expansion relative to the cement causing separation or debonding of the casing from the cement. This process can cause the formation of a micro-annulus between casing and cement that will allow gas flow to the surface or to other lower pressure zones. Mechanical impacts experienced while tripping drill collars, stabilizers, and other tubulars can also cause cracks to develop in hardened cement. All of these operations can cause sustained casing pressure conditions to develop.
Finally, sustained casing pressure can be created by leakage from formations above the top of cement. During the cementing process lost circulation can occur and cause the top of cement to be lower than the position desired. As a result, some productive formations may not be covered by the cement. Furthermore, formations such as fractured shale, although thought to be non-productive, may be capable of producing sustained, minor amounts of hydrocarbons. The leakage through the wellbore mud from either source can result in sustained casing pressure.
While conventional wellheads typically provide a pressure relief line, which relieves the excess pressure from the “A” annulus (the innermost annuli), they provide no means for relieving the excess pressure from the other annuli, which can be numerous. Indeed, in a typical deepwater well, it is not uncommon to have a conductor casing, a surface casing, and multiple nested other casing strings, e.g., three or more, as well as the production casing, all of which have annuli formed there between, which are subject to the increases in fluid pressure identified above. One possible solution to this problem suggested by MMS is to modify existing wellheads, e.g., by providing one or more pressure relief lines that connect to, and bleed pressure from, each of the remaining annuli. A drawback of such a solution, however, is that it would be very expensive to implement, as wellhead design is quite complex and expensive.
Another solution is to employ expensive high-grade (i.e., high strength) casing for each layer of the casing and production tubing. A drawback to this solution, however, is that it also considerably increases the cost of completing the well given that often times thousands of feet of piping are employed in each deep well. Yet another but similar solution is to employ heavier casing (i.e., thicker) with a reduced internal diameter. A drawback of this solution is that the production flowpath is smaller than it could otherwise be, which in turn results in a less efficient production flow. If a certain production flowpath cross-sectional area is required, a larger bore would have to be drilled, which lengthens the required drill time at considerable extra cost. If a certain production flowpath cross-sectional area is not required, the reduced casing internal diameters would require smaller tools to be used to drill and complete lower sections of the well. Procurement of these smaller tools and the limited amount of force that can be applied to them while drilling slows the drilling process and adds further to costs.